Many natural gases and refinery gases from hydrotreating processes contain acid gas components, commonly called "sour" gas components, which form an acidic aqueous solution. It is common to treat or "sweeten" sour gas by removing the sour gas components, hydrogen sulfide (H.sub.2 S) and carbon dioxide (CO.sub.2). The sweetening is almost always required to meet sales and/or environmental specifications.
Hydrogen sulfide is a toxic gas that must be removed to extreme low concentrations (less than 100 ppm) prior to pipeline delivery or burning. Also, when mixed with free water, H.sub.2 S forms a weak acid that can cause corrosion. Carbon dioxide is a non-toxic inert gas. Carbon dioxide, as such, is harmless in dry natural gas, but when mixed with free water will form weak acid and also cause corrosion.
There are generally two types of gas treating processes: (a) absorption and (b) adsorption. The latter involves the removal of a substance from a gas stream by physical binding on the surface of a solid material. In the former process, the gas stream contacts a liquid that selectively removes a substance. The most common absorption process used in gas sweetening is the amine process. The liquid absorbent is a mixture of water and a chemical amine, usually monoethanolamine (MEA) or diethanolamine (DEA). Occasionally, other alkanolamines such as triethanolamine (TEA), diglycolamine (DGA), methyldiethanolamine (MDEA), diisopropanolamine (DIPA), or mixtures of these solutions with one another are employed. Also, other treating solutions such as sulfinol have been employed. Sometimes corrosion inhibitors, anti-foaming agents and/or other special additives are added to the aqueous absorbent solution to improve process efficiencies.
Amines remove carbon dioxide and hydrogen sulfide from a sour gas by a chemical reaction that changes the chemical form of both the amine and the acid gas components. The reaction changes the acid gases into a liquid form which is separated from the acid-free gas or sweetened gas. The chemical reaction between the amine (called lean amine at the start of the process) and acid gases is exothermic, i.e., it gives off heat, when the reaction takes place.
Amine contactors (also called absorbers or scrubbers) are commonly used in absorption gas treatment processes. The purpose of an amine contactor is to contact a gas stream containing hydrogen and/or hydrocarbons with an aqueous amine solution so that the amine removes undesired acid gases from the gas stream. In general, the sweet residue gas flows out the top of a contactor and the reacted amine (also called rich amine) flows out the bottom. Thus, the source gas stream and the aqueous amine flow counter-currently to one another. This counterflow contact maximizes interphasal surface area as well as the concentration gradient between the amine and acid gas reactants. Generally, amine contactors may contain discreet stages, e.g., trays or plate columns, or else have no discreet stages, e.g., spray towers or packed columns.
The flow rate of the amine in the absorption process must be constantly monitored and adjusted based on several factors including: (1) acid gas concentration of the source gas stream, (2) flow rate of the source gas stream, and (3) the degree to which the amine solution has been regenerated, and (4) the amount of acid gas per unit of amine reactant (often called amine loading). Failure to closely monitor these parameters often results in undesired levels of acid gas components in the residue gas. When this residue gas is a refinery gas, which is subsequently burned for fuel, environmentally unacceptable excursions of acid gas components occur.
One method of reducing the incidence of excursions or undesired acid gas concentrations has been to check periodically the acid gas content of the gas exiting the contactor using a Draeger and to adjust the amine flow rate accordingly. Thus, the flow has been increased if the hydrogen sulfide or other acid gas content has been too high. This, however, has had a disadvantage in that once high concentrations of acid gas have been detected, usually some acid gases have already been released into the exiting gas. This method has had a further disadvantage that the amine circulation has often been set to maintain sufficient sweetening at the highest acid gas concentrations, which can result in costly overcirculation and overloading or liquid flooding of the regeneration system during normal operation.
A second method of reducing the incidence of excursions has involved controlling amine flow rate by preselecting the ratio of amine to sour gas. However, intermittent variations in both acid gas and amine concentration often alter the preselected ratio. This method, therefore, has had the same disadvantages discussed above, including excursions and increased operating cost.
A third method has employed an automated control system to adjust the amine flow as required to maintain a desired temperature on a predetermined tray or position in the contactor. This method, however, does not accommodate changes in the temperatures of the streams entering and exiting the tower and thus is also subject to undesired excursions of acid gas components.
There continues to be a need for an improved method for effectively and efficiently controlling the reaction between acid gases and amine absorbents in acid gas removal systems.